A widely used technique for searching for oil or gas is the seismic exploration of subsurface geophysical structures. Reflection seismology is a method of geophysical exploration to determine the properties of a portion of a subsurface layer in the earth, which information is especially helpful in the oil and gas industry. Marine-based seismic data acquisition and processing techniques are used to generate a profile (image) of a geophysical structure (subsurface) of the strata underlying the seafloor. This profile does not necessarily provide an accurate location for oil and gas reservoirs, but it may suggest, to those trained in the field, the presence or absence of oil and/or gas reservoirs. Thus, providing an improved image of the subsurface in a shorter period of time is an ongoing process.
The seismic exploration process consists of generating seismic waves (i.e., sound waves) directed toward the subsurface area, gathering data on reflections of the generated seismic waves at interfaces between layers of the subsurface, and analyzing the data to generate a profile (image) of the geophysical structure, i.e., the layers of the investigated subsurface. This type of seismic exploration can be used both on the subsurface of land areas and for exploring the subsurface of the ocean floor.
Marine reflection seismology is based on the use of a controlled source that sends energy waves into the earth, by first generating the energy waves in or on the ocean. By measuring the time it takes for the reflections to come back to one or more receivers (usually very many, perhaps in the order of several dozen, or even hundreds), it is possible to estimate the depth and/or composition of the features causing such reflections. These features may be associated with subterranean hydrocarbon deposits.
For a seismic gathering process, as shown in FIG. 1, a data acquisition system 10 includes a ship 2 towing plural streamers 6 that may extend over kilometers behind ship 2. Each of the streamers 6 can include one or more birds 13 that maintains streamer 6 in a known fixed position relative to other streamers 6, and the birds 13 are capable of moving streamer 6 as desired according to bi-directional communications birds 13 can receive from ship 2. One or more source arrays 4a,b may be also towed by ship 2 or another ship for generating seismic waves. Source arrays 4a,b can be placed either in front of or behind receivers 14 (shown in FIG. 2), or both behind and in front of receivers 14. The seismic waves generated by source arrays 4a,b propagate downward, reflect off of, and penetrate the seafloor, wherein the refracted waves eventually are reflected by one or more reflecting structures (not shown in FIG. 1) back to the surface (see FIG. 2, discussed below). The reflected seismic waves propagate upwardly and are detected by receivers 14 provided on streamers 6. This process is generally referred to as “shooting” a particular seafloor area, and the seafloor area can be referred to as a “cell”.
FIG. 2 illustrates a side view of the data acquisition system 10 of FIG. 1. Ship 2, located on ocean surface 46 of ocean water 40, tows one or more streamers 6, that is comprised of cables 12, and a plurality of receivers 14. Shown in FIG. 2 are two source streamers, which include sources 4a,b attached to respective cables 12a,b. Each source 4a,b is capable of transmitting a respective sound wave, or transmitted signal 20a,b. For the sake of simplifying the drawings, but while not detracting at all from an understanding of the principles involved, only a first transmitted signal 20a will be discussed in detail (even though some or all of source 4 can be simultaneously (or not) transmitting similar transmitted signals 20). First transmitted signal 20a travels through ocean 40 and arrives at first refraction/reflection point 22a. First reflected signal 24a from first transmitted signal 20a travels upward from ocean floor 42, back to receivers 14. As those of skill in the art can appreciate, whenever a signal—optical or acoustical—travels from one medium with a first index of refraction n1 and meets with a different medium, with a second index of refraction n2, a portion of the transmitted signal is reflected at an angle equal to the incident angle (according to the well-known Snell's law), and a second portion of the transmitted signal can be refracted (again according to Snell's law).
Thus, as shown in FIG. 2, first transmitted signal 20a generates first reflected signal 24a, and first refracted signal 26a. First refracted signal 26a travels through sediment layer 16 (which can be generically referred to as first subsurface layer 16) beneath ocean floor 42, and can now be considered to be a “new” transmitted signal, such that when it encounters a second medium at second refraction/reflection point 28a, a second set of refracted and reflected signals 32a and 30a, are subsequently generated. Further, as shown in FIG. 2, there happens to be a significant hydrocarbon deposit 44 within a third medium, or solid earth/rock layer 18 (which can be generically referred to as second subsurface layer 18). Consequently, refracted and reflected signals are generated by the hydrocarbon deposit, and it is the purpose of data acquisition system 10 to generate data that can be used to discover such hydrocarbon deposits 44. As further seen in FIG. 2, second refracted signal 32a encounters hydrocarbon deposit 44, at third refraction/reflection point 34a, generating third refracted signal 38a, and third reflected signal 36a. Further, second transmitted signal 20b generates first reflected and refracted signals (from second transmitted signal) 24b, and 26b, respectively, at first reflection/refracting point 22b. Second refracted signal 26b encounters solid earth/rock layer 18 at second reflection/refraction point 28b, thereby generating second reflected signal 30b, and second refracted signal 32b. Second refracted signal 32b travels through second layer 18 and encounters hydrocarbon deposit 44 and third reflection/refraction point 34b, and generates third reflected signal 36b and third refracted signal 38b. As those of skill in the art can appreciate, though it appears that this process can continue ad infinitum, such may be technically true and possible, but with each reflection/refraction, only a certain percentage of the energy from the impinging signal is reflected and refracted, and so the strength of the signal diminishes quickly, and can, in fact, after only a few encounters with such interfaces, diminish to the point that the sensitivity of receivers 14 is not large enough to distinguish the signals over other noise in the system. Nonetheless, it is an important part of seismic signal processing to discern different refracted/reflected signals from the noise to the greatest extent possible.
The signals recorded by seismic receivers 14 vary in time, having energy peaks that may correspond to reflectors between layers. In reality, since the sea floor and the air/water are highly reflective, some of the peaks correspond to multiple reflections or spurious reflections that should be eliminated before the geophysical structure can be correctly imaged. Primary waves suffer only one reflection from an interface between layers of the subsurface (e.g., first reflected signal 24a). Waves other than primary waves are known as multiples, and more strictly, are events that have undergone more than one reflection. Typically, multiples have a much smaller amplitude than primary reflected waves, because for each reflection, the amplitude decreases proportionally to the product of the reflection coefficients of the different reflectors (usually layers or some sort). As shown in FIG. 3, discussed below, there are several ways for multiples to be generated.
As illustrated in FIG. 3, seismic source 4 produces first transmitted wave 20a that splits into a primary transmitted wave 26a (referred to also as first refracted signal) penetrating inside first subsurface layer 16 (referred to also as “sediment layer” though that does not necessarily need to be the case) under ocean floor 42, and first reflected signal 24a that becomes surface multiple signal 50 after it interfaces with ocean surface 46 (or fourth interface). Second transmitted wave 20b is reflected once at second interface 48 and becomes second reflected signal 24b, and then is reflected down again from ocean floor 42 to become internal multiple signal 51. Internal multiple signal 51 and surface multiple signal 50 also reaches receiver 14, but at different times. Thus, receiver 14 can receive at least several different signals from the same transmitting event: second reflected signal 30a, surface multiple signal 50, and internal multiple signal 51. Multiples can also be classified as short path multiples, and long path multiples (e.g., surface multiples and internal multiples). Short path multiples are those whose travel path is short compared to the primary reflections, and long path multiples are those whose travel path is long compared to the primary reflections. One type of short path multiples include ghosts 52, in which the seismic energy or wave is transmitted upwards first towards a reflecting boundary layer, then down, and up again to the receiver. As seen in FIG. 3, ghost 52 leaves source 4, travels upwards and reflects nearly perfectly off ocean surface 46, then down to ocean floor 42, and up to receiver 14. Because of the near perfect reflectivity of ocean surface 46, the magnitude of ghosts 52 rivals that of “true” reflected signals 24 and thus are typically very important to marine seismic exploration. As such, ghosts 52 can be very strong.
As is apparent from FIG. 3, the timing of the received signals will depend on the depth of the ocean 40, its temperature, density, and salinity, the depth of sediment layer 16, and what it is made of. Thus, receiver 14 can become “confused” as to the true nature of the subsurface environment due to reflected signals 30, and multiple signals 50, 51, and 52. As briefly discussed above, other multiples can also be generated, some of which may also travel through the subsurface. A multiple, therefore, is any signal that is not a primary reflected signal. Multiples, as is known by those of ordinary skill in the art, can cause problems with determining the true nature of the geology of the earth below the ocean floor. Multiples can be confused by data acquisition system 10 with first, second or third reflected signals. Multiples do not add any useful information about the geology beneath the ocean floor, and thus they are, in essence, noise, and it is desirable to eliminate them and/or substantially reduce and/or eliminate their influence in signal processing of the other reflected signals so as to correctly ascertain the presence (or the absence) of underground/underwater hydrocarbon deposits.
Internal multiple signals 51 typically arise due to a series of subsurface impedance contrasts. They are commonly observed in seismic data acquired in various places, such as the Santos Basin of Brazil. They are often poorly discriminated from the primaries (i.e., the first, second and third reflected signals, among others), because they have similar movement, dips and frequency bandwidth, thereby making attenuation and/or elimination of internal multiple signals 51 (as well as surface multiples 50) one of the key issues in providing clear seismic images in interpreting areas of interest. Over time, various methods have been developed to address this difficult problem and most of them rely on the ability to identify the multiple generators.
The acquisition of data in marine-based seismic methods usually produces different results in source strength and signature based on differences in near-surface conditions. Further data processing and interpretation of seismic data requires correction of these differences in the early stages of processing. Surface-Related Multiples Elimination (SRME) is a technique commonly used to predict a multiples model from conventional flat streamer data. Attenuating the surface-related multiples is based on predicting a multiples model, adapting the multiples model and subtracting the adapted multiples model from the input streamer data.
FIG. 39 depicts schematically a land seismic exploration system (system) 70 for transmitting and receiving vibro-seismic waves intended for seismic exploration in a land environment. At least one purpose of system 70 is to determine the absence, or presence of hydrocarbon deposits 44, or at least the probability of the absence or presence of hydrocarbon deposits 44. System 70 comprises a source consisting of a vibrator 71 (source and vibrator being interchangeable terms for the same device) operable to generate a seismic signal (transmitted waves), a plurality of receivers 72 (or geophones) for receiving seismic signals and converting them into electrical signals, and seismic data acquisition system 200′ (that can be located in, for example, vehicle/truck 73) for recording the electrical signals generated by receivers 72. Source 71, receivers 72, and data acquisition system 200′, can be positioned on the surface of ground 75, and all interconnected by one or more cables 72. FIG. 39 further depicts a single vibrator 71, but it should be understood that source 71 can actually be composed of multiple or a plurality of sources 71, as is well known to persons skilled in the art. As can be further appreciated by those of skill in the art, land related acquisition methods include all land acquisition methods, and in particular land acquisition schemes where receivers and sources (natural or man-made) can be either on or close to the surface (topography) or in the subsurface (in particular along well paths).
In operation, source 71 is operated so as to generate a vibro-seismic signal. This signal propagates firstly on the surface of ground 75, in the form of surface waves 74, and secondly in the subsoil, in the form of transmitted ground waves 76 that generate reflected waves 78 when they reach an interface 77 between two geological layers. Each receiver 72 receives both surface wave 74 and reflected wave 76 and converts them into an electrical signal in which are superimposed the component corresponding to reflected wave 78 and the one that corresponds to surface wave 74, the latter of which is undesirable and should be filtered out as much as is practically possible.
An example of a vibratory source 71 is shown in FIG. 40. Source 71 can include base plate 88 that connects to rod 80. Rod 80 includes piston 82 inside reaction mass 84. Insulation devices 86 can be provided on base plate 88 to transmit weight 90 of vehicle 73 to base plate 88. Base plate 88 is shown in FIG. 40 as lying on ground 75. The force transmitted to ground 75 is equal to the mass of base plate 88 times its acceleration, plus the weight of reaction mass 84 times its acceleration. The weight of vehicle 73 (shown in FIG. 39) prevents base plate 88 from losing contact with ground 75. Many designs for vibratory sources 71 exist on the market, and any one of them can be used with the novel features discussed herein.
Velocity model building remains a crucial step in seismic depth imaging for both land and marine seismic imaging. As those of ordinary skill in the art can appreciate, in order to provide a representative image of the geographical area of interest (GAI), i.e., in order to properly interpret the seismic waves to provide accurate seismic images, it is necessary to have a well-defined velocity model of the general area. However, in order to create a well-defined velocity model of the general area, it is also sometimes, perhaps always, necessary to have an accurate description of the geological physical structures in the area; this presents the classic problem of what is developed first, and how can it be trusted to provide the correct information? A general drawback of conventional tomographic approaches is that the estimated velocity models do not conform enough to the structures (i.e., the geological physical structures underwater and/or underground, including even different layers of subsurface areas).
There are certain problems, however, with determining accurate velocity models using current methods and system, especially when knowledge of the underwater and/or underground structures is not known. Accordingly, it would be desirable to provide methods, modes and systems for using high definition tomography to develop enhanced velocity models for geographical areas of interest.